A common method of increasing productivity of a hydrocarbon-bearing formation penetrated by a wellbore is to subject the formation to stimulation techniques, such as hydraulic fracturing. In hydraulic fracturing, a liquid, gas or two-phase fluid, generally referred to as a fracturing fluid, is introduced into the formation. The fracturing fluid, typically water or oil-based, is introduced into the wellbore penetrating the formation at a sufficient pressure and flow rate to create fractures in the subterranean formation. A proppant is introduced into the fractures to keep the fractures open. The propped fracture provides larger flow channels through which an increased quantity of a hydrocarbon may flow, thereby increasing the productive capability of the well.
Recently, ultra lightweight (ULW) particulates have been reported for use as proppants. The requisite fluid velocity to maintain proppant transport within the fracture is reduced by the use of ULW proppants. In light of reduced fluid velocity, a greater amount of the created fracture area may be propped. Exemplary of such ULW proppants are those set forth in U.S. Patent Publication No 2008/0087429 A1, herein incorporated by reference.
Many times, fracturing proceeds by first introducing into the formation a “pad” or “spearhead” fluid. Pad or spearhead fluids are fracturing fluids used to initiate fractures and are typically free of proppant. They normally exhibit relatively low viscosity. Following the initiation of the fracture, fracturing fluid containing proppant is then introduced into the formation.
Fracturing fluids which are predominately liquid typically exhibit poor transport properties. High pumping rates are normally required in order to impart a sufficient velocity for placement of the proppant in the fracture. In such treatments, the proppant tends to settle, forming a ‘proppant bank’, as the linear slurry velocity falls as a function of the distance from the wellbore. This effect is further believed to result in reduced stimulation efficiency as the effective propped length is relatively short.
Further complications arise from the use of liquid fracturing fluids because of the need to recover the fracturing fluid. Such fracturing fluids typically contain components which are damaging to the environment and/or affect the production of oil and/or gas from the reservoir. For instance, water soluble polymers, such as guar gum or a derivative thereof, are often used in fracturing fluids to provide the requisite flow characteristics to the fluid and to suspend proppant particulates. When pressure on the fracturing fluid is released and the fracture closes around the proppant, water is forced out and the water-soluble polymer forms a filter cake. This filter cake can prevent oil or gas flow if it is not removed. Further, emulsions may be generated from fracturing fluids which impede flow of produced gas and/or oil.
The recovery of fracturing fluids and the removal of filter cakes is normally accomplished by reducing the viscosity of the fluid with a breaker such that the fracturing fluid flows naturally from the formation under the influence of hydrostatic pressure. Historically, the application of breakers in fracturing fluids at elevated temperatures, i.e., above about 120-130° F., has been a compromise between maintaining proppant transport and achieving the desired fracture conductivity, measured in terms of effective propped fracture length. Conventional oxidative breakers react rapidly at elevated temperatures, potentially leading to catastrophic loss of proppant transport. Encapsulated oxidative breakers have experienced limited utility at elevated temperatures due to a tendency to release prematurely or to have been rendered ineffective through payload self-degradation prior to release.
Alternative fracturing treatments have been explored by incorporating gaseous materials into fracturing fluids in order to form a gas phase at the wellhead or at the formation being fractured or both. In “foam fracturing”, a foam is generated of a desired Mitchell quality which is then introduced through the wellbore into the formation. For instance, U.S. Pat. No. 3,937,283 discloses a hydraulic fracturing process employing a foam formed of a gas (such as nitrogen, carbon dioxide, air or a hydrocarbon gas) and a liquid (such as water or an oil base liquid). The foam is characterized as having a foam, or Mitchell, quality within the range of 52.4% to 99.99% and preferably between the ranges of 60% to 85%. The pressure at which the foam is pumped into the well is such that a fracture of the hydrocarbon-bearing formation is created. The foam easily exits the well when pressure is released from the wellhead. The reduction in pressure causes the foam to expand.
It is known that in order to successfully carry proppant particulates into a formation, the foamed fluid must exhibit a fine, uniform texture rather than a coarse texture. Over a foam quality of 85%, foamed fluids have been known to exhibit a coarse structure. Coarse textures destabilize the foam, causing the foam to disintegrate and break apart. In addition to increasing stability of the foam, a fine texture is also known to affect viscosity of the foam. With fine textured foams defined by bubbles of small diameter, interaction amongst the bubbles increases which, in turn, increases the viscosity of the fluid.
Further, conventional fracturing operations, including those wherein a gaseous material is incorporated into the fracturing fluid, have been found to be inappropriate for the creation of partial monolayer fractures. Partial monolayer fractures are created by a proppant pack having proppant particulates widely spaced from each other, the proppant pack exhibiting the requisite strength to hold fractures open and thus allow the production of hydrocarbons from the formation.
The efficiency of a partial monolayer fracture is dependent on fracture porosity and conductivity once the fracturing operation is stopped and production commences. Fracture porosity is dependent upon the area concentration of the proppant placed, the proppant size, and mechanical properties, e.g., modulus, of the proppant. It is important that proppant packs forming partial monolayer fractures exhibit high porosity. The high conductivity of the created fractures is attributable to the ability of produced fluids to flow around the widely spaced proppant particulates instead of being confined to the relatively small interstitial spaces evidenced in the packed proppant bed.
Alternative hydraulic fracturing methodologies have been sought which provide increased conductive fracture areas and increased effective propped fracture lengths. Such alternative methodologies need to render improved stimulation efficiency and well productivity and provide a means to create partial monolayer fractures. In addition, such methodologies need to minimize or eliminate the reservoir damage evidenced from the use of liquid fracturing fluids.